Production fluids, oil and natural gas, from a reservoir are recovered by drilling wells at a spacing which allows for optimal recovery. Optimization is based on the characteristics of the reservoir rock, fluids, and the pressure along with cost of the wells. The natural permeability of the rock allows for fluid flow through the rock from regions of higher to lower pressure. Rock with low permeability may contain significant quantities of production fluids. The longer the path from the fluids at high pressure in the rock to a low pressure region in the well, the greater the restriction on production rate from that rock. The lower the permeability of the rock for a given fluid pressure and path length, the sooner production will drop off. While the fluids will continue to migrate through the low permeability rock from the residual high to low pressure region, the production rate of the well may not produce sufficient financial resources to warrant further recovery which will leave reserves in the ground as unrecoverable.
Natural fissures in the rock provide pathways of greater permeability and can allow production fluids to move along more efficient paths from the reservoir rock to the well bore if the well bore communicates with these natural fissures. Initial rates of recovery may not be improved significantly, but the period over which the rate remains higher and, therefore, more economically viable to recovery is extended. This, in turn, allows for greater drainage of the reservoir since any given segment of the high pressure fluids trapped in the low permeability rock will have a shorter pathway to travel before being recovered. However, even under these conditions the total reserves which are economically recoverable may be limited by the permeability of the rock and the distance any portion of the reservoir fluid must travel through that rock before encountering a natural fissure which communicates with the well bore.
Most reservoirs exhibit greater horizontal dimensions than vertical. A single well drilled vertically through a reservoir provides for communications between the well and the reservoir rock only in association with the vertical dimension. Such wells are most often completed by cementing steel casing to the well bore and perforating the steel and cement using small shaped charges spaced within the vertical dimension. If the rock has low permeability as discussed above, the rate of production is limited by the communications these perforations have with naturally occurring fractures or the movement of the fluid through the rock itself.
To increase the likelihood of communications with natural fractures or the reservoir rock, technologies and methodologies for deviating from vertical wells to horizontal wells were developed. This allowed the well bore to be changed from vertical to horizontal such that it extended through the reservoir taking advantage of the larger horizontal dimensions. Such wells may be completed as with vertical wells having casing cemented along the length of the horizontal segment and perforated extensively, or the horizontal segment may be left open hole. Each method has its advantages. However, once completed, the well will be in communication with a set number of natural fissures or reservoir rock. While improved, the well will encounter reductions in production rate over time and economically recoverable reserves will be somewhat better, but not as much as available.
Hydraulic fracturing has been developed to enhance communication between the reservoir and the well bore. Hydraulic pressure is applied to the formation through perforations in a cemented and cased segment of either a horizontal or vertical well bore. This pressure causes the formation rock to fracture opening new pathways for the production fluids to flow. In many cases, these fractures are enhancements to or intersect with natural fractures as is seen by their preferential orientation with the existing stresses in the formation. Like many naturally occurring fractures, hydraulic fractures may close up upon release of the hydraulic pressure allowing the rock to reduce or eliminate the channel created. To mitigate this, proppant such as sand or ceramics is pumped into the well to prevent this closure from fully occurring. The resulting propped segment of the fracture will have permeability associated with the specific proppant at the formation closure pressures. Studies indicate that while the hydraulic fractures may extend for as much as 1000 feet, proppant tends to settle out of the fracturing fluid in approximately 200 feet. This means that communications is significantly less than that possible due to the hydraulically produced fracture and that fewer natural fractures are encountered by the usable hydraulic fracture.
While limited, these advances in reservoir recovery have made significant improvements to the rate of production, drop-off rate, and total recoverable reserves. They have, in fact, opened up reserves that were heretofore not considered economically recoverable. The maturation of the technologies has also allowed reservoir and well engineers to improve designs of well spacing of a field.
Assuming the value of produced fluids and the cost of a given well design, not only can the well be optimized, but also the spacing of those wells. Since wells are expensive to drill and being able to drain a larger area from a single well would mean fewer wells, there is significant savings resulting from further improvements. Additionally, increasing communications with the reservoir in a cost effective manner would increase the rate of production, decrease the rate at which this rate declines, and generally make a larger portion of the possible reserves to be considered recoverable.
However, once designed, drilled, and completed, wells are not normally enhanced. Some wells which were never fractured have resulted in improving recovery. If the economics of recovery change, then more wells are normally drilled with all the commensurate costs.
While this discussion has focused on wells drilled in low permeability rock, it generally applies as well to wells with higher permeabilities, especially if the reservoir pressure has been depleted. While there may be more production fluid in the reservoir, it may be non-recoverable due to the loss of motivating pressures. This has resulted in secondary recovery methods such as pumping to reduce the low side backpressure and tertiary recovery that stimulates movement by creating various sources of pressure or chemical gradients such as with water or CO2 flood. Both cases would benefit from improved communications between the well and the reservoir rock. In the case of tertiary recovery where there is normally a stimulation well, such as a water injection well, enhanced communications would benefit both the stimulation as well as production wells.
Recovery from wells containing rock or bituminous materials, such as tar sands and carbonatious reservoirs, are often stimulated into recovery by Steam Assisted Gravity Drained (SAGD). In this method, a horizontal well is drilled in the reservoir above and parallel to another horizontal well. Steam is injected into the higher well reducing the viscosity of the hydrocarbons in the rock and allowing them to flow through the rock to the lower well for capture and recovery. While effective, this technique is constrained by the possible size of the steam plume within the rock, the distance between the upper and lower wells, and their possible spacing. Here, natural fractures or their simulation would not be of as significant value as simply more wells parallel to one another. But, economics dictate the initial and, often, final spacing.
Well costs dictate the well design and spacing for a given reservoir and assumed production fluid value. Once produced, few fields can be significantly improved without drilling additional wells on smaller spacing. For any given well design, most often the most significant cost of the well is in completing that portion which is simply there to get to the reservoir, the vertical component. Often a well will be 6,000 to 8,000 feet Total Vertical Depth (TVD) and extend only 1,000 feet horizontally with the vertical and turning segments of the well cemented and cased. The cost of drilling and completion often prevent multiple horizontal segments off the same vertical well and when it is done, only a few are drilled. An additional pressure on further drilling from a given well is the delay to getting it into production. Wells not connected to the production system do not produce revenue but only cost.
It would, therefore, be beneficial to have a system and method that could create more intimate contact with the reservoir, do so without the need for adding the vertical component of a well, and allow for continued improvement to the well over time without effecting production.
Drilling while producing has been employed in the past primarily as a result of underbalanced drilling techniques. It reduces reservoir damage during production and provides some revenue in the process. But it is not employed once the well is completed.
To increase the communications between the well and the reservoir, a system is needed to increase the total surface of the production rock in contact with a connection to the well bore or the number of natural or hydraulic fractures connected to the well bore. This can be accomplished by adding more well bore to the existing well. In addition to drilling a limited number of additional horizontal wells segments from a single vertical well, in the past one such technique employed has been coil tube drilling to produce herringbone extensions from an existing well. While a coil tube can add total well bore surface area, it has been limited by the length of the coil tube, its cost due to the limited number of times a single coil can be reused, and the requirement that the well not be in production at the time of drilling. Coil tube drilling has also been used to re-enter a well to add herringbone segments. While this adds applicability to the technique, it does not resolve the inherent limitations listed.
Whether using coil tube or conventional drilling methodology to produce an additional well bore, the well must be off production with the exception of the temporary and unusual underbalanced drilling technique. This motivates completing the well and not reopening it for further changes or improvements unless absolutely necessary.
An innovative approach would be to create a device and its method of use to allow continuous improvement of an initial well, horizontal or vertical, without requiring the well to be removed from production. This implies an automated or robotic system that operates continuously subsequent to the well being placed into production.
Robotics has been applied to drilling, but the majority of approaches have been to provide safer and more effective automation of surface activities. Automated tongues for breaking and joining drill stems are an example. Automaton and robotic handling of drill stems or collars have also been developed. A number of drilling rigs have been nearly fully automated and could even be considered to be partially robotic by essentially executing the same tasks that have otherwise been done by a trained crew. Some off-shore platforms provide a combination of these capabilities along with very sophisticated and automated controls for platform positioning.
Down-hole robotics have been limited. In one unpublished study, a drilling robot was developed which was tethered to a power and control system. As the robotic drill created a hole by the drill bit at the front end, it passed the cuttings to the back of the robot where it attempted to pack them into the hole already made. This effort failed due to entropy in that for hard rock it was impossible to continue the process without ultimately sticking the robot. A second commercial system that was to drill a specific and relatively short distance straight down into a formation suffered from much the same difficulties sticking in the hole before achieving the desired depth. The US military has also used robotic drilling systems that were un-tethered and designed to penetrate hard rock a short relatively short distance. In this case, the power for the drill produced significant exhaust which was used to clear the hole. However, this system was limited to single shallow dry hard rock holes. None of these efforts showed the essential integration of features to allow continuous drilling and improvement to an existing well. Instead, they indicated that a robotic system must include disposal or otherwise resolution of the cuttings accumulation and control of the drilling system. In the case of a clean hole, a tether was an acceptable feature and more desirable than a single use system.
Control of a robot down-hole would depend on sensors that could detect position, orientation, and distance traveled. Pipe robots offer methods of discerning these position characteristics and, with increased sophistication in directional drilling, techniques can be applied to properly locate all components down hole. A particular advantage that an integrated system would have is the potential for cooperation between components.
In addition, sensors could be added that also detect formation characteristics and inform further progress which is managed either autonomously or by intervention. In fact, a robotic sub-surface sensor platform has been proposed which has a tethered component and the ability to allow an individual robotic sensor package to move into the formation, gather information, and return for download. This system acts as essentially a wire-line system with the addition of robotic sensor gathering packages. Much like the pipe robots or the sub-surface positioning systems in existence, the robotic sensor package provides no more than insight into relevant sensors for surveying that may facilitate a fully integrated robotic drilling system. Additionally, all these systems require ongoing operations or production to cease while they are in use.
What is needed is a robotic drilling system which, while the well remains in production, can be operated continuously in order to produce an additional well bore for improved communications between the main well bore and the reservoir rock, natural fractures, or hydraulic fractures. Any drilling component of the system must have one or more methods of eliminating cuttings to reduce the chance of the drilling device sticking in the hole it creates. The system should provide for sufficient sensory data to allow automation of the device and component positioning, relative positioning, orientation, and condition. Furthermore, the device should allow integration of appropriate real-time sensors which will allow for improvement of the drilling and positioning process within the reservoir.